Natural gas comprises different hydrocarbons in varying amounts, plus varying amounts of nitrogen, carbon dioxide, and sometimes hydrogen sulfide. If the percentage of condensable hydrocarbons, that is, those that can ordinarily be collected and stored in liquid form, for example, ethane, propane, butane, and the like, is low, then the gas is called "dry" gas. On the other hand, if there is present in this natural gas a sufficient amount of the condensable hydrocarbons as to make their recovery economically feasible, then the gas is called "wet" gas.
In the case of a typical "wet" gas, a production facility can effect a separation of produced fluids into a residue gas stream containing predominantly methane and some C.sub.2 through C.sub.8 hydrocarbons, for example, and a condensate stream containing predominantly heavier hydrocarbons, for example, C.sub.5 and heavier hydrocarbons. If there are sufficient C.sub.2 through C.sub.8 hydrocarbons in the residue gas stream to economically justify natural gas liquids recovery, then the residue gas stream from the production facility can be further processed downstream in a natural gas processing plant for natural gas liquids recovery. Thus, in the case of a typical "wet" gas, recovery of natural gas liquids will or will not be desirable, depending upon whether or not there are sufficient natural gas liquids available in the residue gas stream to economically justify the construction and operation of a natural gas processing plant downstream of the production facility.
The processing of fluids from a gas-condensate well, however, presents a different set of considerations. A gas-condensate field is one in which the hydrocarbons exist in a vapor state under high pressure. When this vapor comes to the surface and the pressure is reduced, almost all of the condensable hydrocarbons may be transformed into a liquid which may include small amounts of methane and ethane, while almost all of the methane and ethane and some of the condensable hydrocarbons remain as a gas. The condensate contains, as well as natural gasoline (that is, butanes plus pentanes, hexanes, heptanes, and some octane) and lighter hydrocarbons (for example, C.sub.2 -C.sub.4 hydrocarbons), some heavier hydrocarbons in the C.sub.9 -C.sub.25 range or even higher, such as, for example, naphtha, kerosene, mineral seal, or absorption oil and fuel oil. In this case, surface facilities would be mandatory to meet sales product specifications either production facilities or downstream natural gas processing facilities for each of the possible products, such as, for example, gas sales, natural gas liquids sales, and condensate sales. The controlling specifications would be (1) for gas sales--hydrocarbon dewpoint; (2) for condensate sales--Reid Vapor Pressure and flow rate; and (3) for natural gas liquids sales--flow rate, methane content, carbon dioxide content, and ASTM endpoint. The desired goal of such surface facilities would be to meet product specifications with minimal energy requirements and with minimal losses.
In the case of produced fluids from high pressure gas condensate wells, moreover, some form of hydrocarbon recovery at a production facility, as distinguished from a downstream natural gas processing plant for NGL recovery, is mandatory since the natural gas cannot be sold unless these heavier hydrocarbon components which could condense and cause problems in normal operation of the pipeline from the production facility are removed. The cost of this recovery is an additional cost of producing and selling the natural gas. These heavier hydrocarbons have been partially scrubbed out in conventional production facilities and sold as natural gas liquids without meeting natural gas liquids specifications, resulting in a monetary penalization, or have been sent to a downstream natural gas liquids processing unit to achieve specification natural gas liquids.
In many situations where high pressure gas condensate reservoirs are produced only two salable products have been recovered, that is, gas and condensate. In such situations, disposal of the intermediate hydrocarbons which would be important constituents of the natural gas liquids (primarily propane and butane, but also including ethane and higher hydrocarbons) can be a problem. If these hydrocarbons were to be added to the condensate, the condensate product may not meet its vapor pressure specification. If the hydrocarbons were to be left in the gas stream, the hydrocarbon dewpoint specification of the residue gas stream may be in jeopardy.
One type of conventional production facility which can be used to process a wellhead stream produced from a high pressure gas condensate reservoir, known as a central tank battery (CTB), involves flashing down the high pressure gas condensate produced stream to remove the condensate and separate a residue gas which meets hydrocarbon dewpoint specification. In such a facility, the full produced fluid stream can enter high pressure separators for an initial stage of separation usually operated at about 600-1000 psi and 10.degree.-20.degree. F. above the hydrate temperature. The resulting condensate can then be flashed to an intermediate pressure separator operating at about 50 to about 300 psi. The gas from the intermediate pressure separator can then be compressed and recombined with the high pressure separator gas. The intermediate pressure condensate can then be flashed and heated in a low pressure separator or heater treater to about 20-50 psi and 110.degree.-125.degree. F. The resulting condensate can then be flashed to atmospheric pressure for storage in tanks. A vapor recovery unit can compress the gas from the storage tanks and combine this gas with gas from the heater treaters. The resulting combined gas can then be compressed and mixed with the gas from the intermediate separator. The heater treater of such a central tank battery (CTB) is utilized to drive off light ends to meet the condensate product vapor pressure specification and to make water separation easier. A condensate which contains significant amounts of intermediate hydrocarbon components will have a relatively high horsepower requirement. The horsepower requirements can be very large because recycle streams in such a central tank battery (CTB) facility can build up as offgas from the intermediate separators and heater treaters are recompressed to pipeline pressure followed by cooling causing condensation. The condensed liquids returned to the various separators are the source of the recycle. Such central tank battery (CTB) facilities can produce a residue gas meeting hydrocarbon dewpoint specification. The intermediate hydrocarbons can be partially scrubbed out and sold as NGL (natural gas liquids) without meeting specification, but monetarily penalized, or sent to a processing unit to achieve specification NGL.
To reduce the recycle problems of the central tank battery (CTB), a deethanizer can be added to process liquids separated in compressor scrubbers. The addition of the deethanizer allows a specification NGL product to be produced. However, some operational difficulties can be encountered. Choke heaters may be required on high pressure streams flashed to lower pressures in order to prevent hydrate formation. Also, depending on the composition and production pressure levels, gases may have conditions near their critical region during compression and cooling. This can result in erratic levels in the scrubbers operating in this critical region.
With higher energy prices, however, more efficient separation techniques not subject to these problems are in demand for recovery at a production facility of stabilized condensate and specification NGL from natural gas produced from high pressure gas condensate reservoirs. As can be appreciated from the above description, conventional processes such as central tank battery (CTB) facilities can require a large amount of compression and are therefore inefficient. Similarly, as indicated, there are a number of potential problems in utilizing the central tank battery (CTB) with deethanizer system. A demand therefore exists for a stabilization process that is more efficient than these past processes and which is capable at a production facility of producing specification residue gas and natural gas liquids as well as specification stabilized condensate products. The present invention meets these requirements in an efficient and economical manner and avoids the problems presented by the past processes.